CHAPTER III

BEHAVIOR OF HYDROCARBONSIN THE SUBSURFACE

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CHAPTER III

BEHAVIOR OF HYDROCARBONS IN THESUBSURFACE

The purpose of this chapter is to supplement your knowledge ofhydrocarbon behavior in the subsurface. This basic information lays thefoundation for the principles and concepts used in the design of effectiveand efficient free product recovery systems.

The fate-and-transport of liquid petroleum products in thesubsurface is determined primarily by the properties of the liquid and thecharacteristics of the geologic media into which the product has beenreleased. Important liquid properties include density, viscosity andinterfacial tension. Soil properties that influence the movement ofpetroleum hydrocarbons include porosity and permeability. Otheradditional properties, which are functions of both the liquid and the media,include capillary pressure, relative permeability, wettability, saturation, and residual saturation. Site-specific physical conditions (e.g., depth togroundwater, volume of the release, direction of groundwater flow) alsocontribute to the migration and dispersion of released petroleum products. This chapter contains discussions of each of these factors. To put thefollowing discussion in the context of the types of petroleum hydrocarbonscommonly found at UST sites, we begin with a brief description of theclassification and composition of hydrocarbons.

Classification And Composition Of Hydrocarbons

Petroleum hydrocarbons are derived from crude oil, which isrefined into various petroleum products by several processes. Like theparent crude oil, refined petroleum products are also mixtures of as manyas several hundred compounds. The bulk products may be classified on thebasis of composition and physical properties. Products typically stored inUSTs include the following main groups:

! Gasolines! Middle Distillates! Heavy Fuel Oils

Exhibit III-1 presents a gas chromatogram of a hydrocarbon sample withthe approximate ranges in which the various constituents fall. Compoundsoutside the normal ranges depicted are commonly found as contaminants

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Exhibit III-1

Gas Chromatogram Showing Approximate RangesFor Individual Hydrocarbon Products

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in other products. For example, diesel fuel may contain minor amounts ofbenzene and other light hydrocarbons.

Gasolines

Gasolines are mixtures of petroleum hydrocarbons and other non-hydrocarbon chemical additives, such as alcohols (e.g., ethanol) and ethers(e.g., methyl tertiary-butyl ether, or MTBE). Gasolines are more mobilethan either the middle distillates or the fuel oils. The higher mobility ofgasoline is primarily due to the fact that its components tend to have lowermolecular weights; hydrocarbon compounds usually found in gasoline havebetween 4 and 10 carbon atoms per molecule. The lower molecular weightresults in lower viscosity, higher volatility, and moderate water solubility. Fresh gasolines contain high percentages of aromatic hydrocarbons (i.e.,those with a 6-carbon benzene ring), which are among the most soluble andtoxic hydrocarbon compounds. The most frequently encountered aromaticcompounds are benzene, toluene, ethylbenzene, and xylene (BTEX). Because of their relatively high volatility, solubility, and biodegradability,BTEX compounds are usually among the first to be depleted from freeproduct plumes. At sites of older gasoline releases, the free product plumemay contain relatively little BTEX, being instead enriched in heavier, lesssoluble, and less readily biodegradable components. As a consequence, theproduct will be more viscous, slightly more dense, less volatile, and lessmobile than fresh product. The non-hydrocarbon additives (e.g., ethanol,MTBE) are readily soluble and preferentially dissolve into groundwater,which diminishes their concentration in the free product, but results information of longer dissolved plumes. MTBE also moves away from thesource faster than free product and because it is relatively non-degradable,it is difficult to remediate. Discussion of methods to remediate dissolvedplumes are beyond the scope of this manual.

Middle Distillates

Middle distillates (e.g., diesel fuel, kerosene, jet fuel, lighter fueloils) may contain 500 individual compounds, but these tend to be moredense, much less volatile, less water soluble, and less mobile than thecompounds found in gasolines. The major individual components includedin this category of hydrocarbons contain between 9 and 20 carbon atomseach. Lighter aromatics, such as BTEX, are generally found only as traceimpurities in middle distillates, and if initially present, they are generally notpresent in plumes at older release sites, because they have biodegraded,evaporated, and dissolved into groundwater.

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Heavy Fuel Oils

Heavy fuel oils and lubricants are similar in both composition andcharacteristics to the middle distillates. These types of fuels are relativelyviscous and insoluble in groundwater and are, therefore, fairly immobile inthe subsurface. Most of the compounds found in heavy fuel oils have morethan 14 carbon atoms; some have as many as 30. Like the older releases ofmiddle distillates and gasolines, the lighter end components are presentonly in trace amounts as they are more readily biodegraded and dispersed.

Phase Distribution In The Subsurface

The petroleum hydrocarbon constituents that comprise free productmay partition into four phases in the subsurface—vapor (in soil gas),residual (adsorbed onto soil particles including organic matter), aqueous(dissolved in water), and free or separate (liquid hydrocarbons). ExhibitIII-2 illustrates the distribution of the hydrocarbon phases in the subsurfacefrom a leaking UST. The partitioning between phases is determined bydissolution, volatilization, and sorption.

When released into the subsurface environment, liquidhydrocarbons tend to move downward under the influence of gravity andcapillary forces. The effect of gravity is more pronounced on liquids withhigher density. The effect of capillary forces is similar to water beingdrawn into a dry sponge. As the source continues to release petroleumliquids, the underlying soil becomes more saturated and the leading edge ofthe liquid migrates deeper leaving a residual level of immobilehydrocarbons in the soil behind and above the advancing front. If thevolume of petroleum hydrocarbons released into the subsurface is smallrelative to the retention capacity of the soil, then the hydrocarbons willtend to sorb onto soil particles and essentially the entire mass will beimmobilized. For petroleum hydrocarbons to accumulate as free producton the water table, the volume of the release must be sufficient toovercome the retention capacity of the soil between the point of release andthe water table. Without sufficient accumulation of free product at thewater table, there is no need for a free product recovery system. However,in either case, there may be a need for appropriate remedial action tomitigate the residual (sorbed) phase so that it does not continue to act as alingering source of soluble groundwater contaminants or volatile, andpotentially explosive, vapor contaminants. Exhibit III-3 illustrates theprogression of a petroleum product release from a leaking UST. Frame Ashows the hydrocarbon mass before it reaches the capillary fringe. If therelease were to be stopped at this point, there would

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Exhibit III-2

Vertical Distribution Of Hydrocarbon Phases

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Exhibit III-3

Progression Of A Typical Petroleum Product Release From An Underground Storage Tank

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probably be no accumulation of free product. In Frame B, the release hascontinued and the volume of the release is sufficient for free product tobegin accumulating on, and displacing, the capillary fringe. The freeproduct is beginning to displace the capillary fringe and some of the solubleconstituents are dissolving into the groundwater. The source of release hasbeen stopped in Frame C. Residual hydrocarbons remain in the soilbeneath the UST. The free product plume has spread laterally, and a plumeof dissolved contaminants is migrating downgradient.

Portions of the hydrocarbon mass from both the residual and freephases will volatilize (evaporate) and solubilize (dissolve) to becomecomponents of the soil vapor and groundwater, respectively. Volatilizationand solubilization of the lighter fractions tend to make the remaininghydrocarbon mass more dense and even less mobile. Hydrocarbons thatare in the vapor phase are much more mobile and can migrate relativelygreat distances along preferential flow paths such as fractures, joints, sandlayers, and utility line conduits. Accumulation of vapors in enclosedstructures (e.g., basements, sewers) potentially can cause fires orexplosions. The more soluble components of the hydrocarbon mass willdissolve into groundwater, both above and below the water table. Thedissolved hydrocarbons move with the flowing groundwater and cancontaminate drinking water supplies. Also, if groundwater is recovered asa result of pumping or skimming, it may require treatment or disposal if theconcentration of dissolved hydrocarbons is higher than the applicablegroundwater or drinking water standard. Vapors may be released from thegroundwater or be drawn directly from the subsurface if vacuum-enhancedfree product recovery systems are employed. These vapors may requiretreatment to mitigate fire or explosion potential and to comply with airquality criteria.

Exhibit III-4 presents estimates of phase distribution from agasoline release into the subsurface consisting of medium sand. Most ofthe amount spilled (64 percent) remains in the free phase; however, thevolume contaminated by residual phase and dissolved phase hydrocarbonsrepresents nearly 99 percent of the total contaminated volume. Perhaps themost important point to note is that a very small quantity of petroleumhydrocarbons (1 to 5 percent of the original release volume) cancontaminate a significant amount of groundwater (79 percent of the totalcontaminated volume). Hence, recovery of as much free product aspossible is important, but only a portion (up to 50 percent) of the freephase hydrocarbon is actually recoverable with the balance remaining in theresidual phase acting as a continuous source of groundwatercontamination. Where a water supply is threatened by a release, recoveryof free product may be only the first step. An adequate remedial actionmay require aggressive remediation of the residual phase as well.

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Exhibit III-4

Phase Distribution At A 30,000-Gallon Gasoline SpillSite In An Aquifer Of Medium Sand

PhaseContaminantVolume (gal) % of Total

ContaminatedVolume (yd3) % of Total

Free Phase 18,500 64 7,100 1

Residual Phase 10,000 35 250,000 20

Dissolved (Water) 333 1 960,000 79

Source:Modified from Wilson and Brown, 1989.

Properties Of Geologic Media

The extent and rate of petroleum hydrocarbon migration depends inpart on the properties of the subsurface medium in which it is released. The subsurface medium may be naturally occurring geologic materials(e.g., sedimentary, metamorphic, or igneous rock or sediments) or artificialfill that has been imported to the site by human activity. In order to designeffective and efficient free product recovery systems, you need tocharacterize both the type and the distribution of geologic media (or fillmaterial) so that you can determine the likely migration routes and traveltimes.

In the context of fluid flow in the subsurface, geologic media can beclassified on the basis of the dominant characteristics of pore space,fractures, or channels through which fluids move. In porous media, fluidsmove through the interconnected voids between solid grains of soil. Fractured media are those in which fluids migrate readily through fracturesrather than the adjacent soil or rock matrix. Fracturing is usuallyassociated with consolidated materials, but it can also occur inunconsolidated clays due to desiccation. Karst media are those in whichfluids flow through solution features and channels (e.g., caves associatedwith carbonate rocks such as limestone).

Porosity and permeability are the two most important media-specific properties of a natural geologic material. Porosity characterizesthe ability of media to store fluids, and permeability characterizes the abilityof the media to transport fluids. Exhibit III-5 summarizes the

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EXHIBIT III-5

Functional CharacteristicsOf Geologic Media Properties

Property Significance

Porosity Porosity is required for calculation of the amount of free productand immobile (residual) product. The relevant parameter fordetermining recoverable free product is the “drainable” or“effective” porosity, which is always less than total porosity.

Permeability Permeability controls the rates of groundwater flow and freeproduct migration. It is also used to calculate pumping ratesrequired for hydraulic control.

Anisotropy Anisotropy is a condition of the geologic media in whichmeasurement of a property (e.g., hydraulic conductivity) dependsupon the direction of measurement. Anisotropy can causegroundwater flow to not be in the same direction as the hydraulicgradient.

Heterogeneity Heterogeneous media often provides preferential pathways forfluid migration—these pathways are difficult to locate and tocharacterize.

significance of geologic properties and their relevance to free productrecovery.

Porosity

Porosity, or more specifically effective (“drainable”) porosity, is animportant factor to be considered in the evaluation of a free productrecovery system. Calculation of the amount of free and immobile productin the subsurface requires a value or estimate of effective porosity.

Porosity defines the storage capacity of a subsurface media. Allrocks and unconsolidated media contain pore spaces. The percentage ofthe total volume of an unconsolidated material or rock that consists ofpores is called porosity. Porosity is classified as either primary orsecondary. Primary porosity, which is created when sediments aredeposited (or crystalline rocks are formed), depends on the shape, sorting,and packing of grains. Primary porosity is greatest when grains are nearlyequal in size (i.e., are well graded or sorted) and nonspherical in shape. Unconsolidated sediments that contain a wide range of grain sizes (i.e., are

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poorly graded or sorted) tend to have a low primary porosity becausesmaller grains fill the pore spaces between the larger grains.

Secondary porosity develops after rocks have been formed orsediments deposited. Examples are joints, foliations, fractures, andsolution openings. Also included in this category are animal burrows, rootholes, and desiccation cracks in clay soils. While the latter examplestypically facilitate free product migration only very locally, the formerexamples can exert a much more regional influence. Characterization ofthe flow of groundwater and free product through solution channels,fractures, and joints can be especially problematic. Wells completed atsites underlain by these features may not accurately (or completely) defineflow directions or rates. The flow of groundwater and free productthrough the larger openings can sometimes even be under conditions ofopen channel flow. Once free product enters these larger openings, it canmigrate undetected over relatively great distances (miles in some cases) in amatter of weeks or months. Although it would potentially be easier torecover free product in such a setting, it is much more difficult (and inmany cases impossible) to locate recoverable accumulations.

Total porosity is based on the volume of all voids (primary andsecondary), whether or not the pores are connected. When pores are notconnected and dead-end pores exist, groundwater cannot move through therock or sediments. Effective porosity is the term that characterizes theratio of the volume of interconnected pores to the total volume ofunconsolidated materials or rock.

There is no direct correlation between effective and total porosity. Effective porosity is approximated by drainable porosity and can besignificantly less than total porosity. In general, the smaller the grains inthe rock, the smaller the effective porosity (and the greater the retentioncapacity or residual saturation). For example, clays and limestones canhave an upper range of total porosity that is in excess of 55 percent (seeExhibit III-6), but a lower range of drainable porosity of 1 percent or less.

Permeability

Permeability is one of the most critical properties to be consideredin the design of any recovery system for free product recovery. The ratesof groundwater flow and free product migration are related directly topermeability. The rate of free product migration also depends on otherparameters, but permeability exhibits the greatest range in values (varyingover 5 or 6 orders of magnitude for common geologic media).

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Exhibit III-6

Porosity Of Various Geologic Materials

MATERIAL NO. OF ANALYSES RANGE ARITHMETIC MEAN

Total Porosity

Sedimentary MaterialsSandstoneSiltstoneSand (fine)Sand (coarse)Gravel (fine)Gravel (coarse)SiltClayLimestone

657

243263815

2817474

0.14 - 0.490.21 - 0.410.26 - 0.530.31 - 0.460.25 - 0.380.24 - 0.360.34 - 0.610.34 - 0.570.07 - 0.56

0.340.350.430.390.340.280.460.420.30

Metamorphic RocksSchist 18 0.04 - 0.49 0.38

Drainable Porosity

Sedimentary MaterialsSandstone (fine)Sandstone(medium)SiltstoneSand (fine)Sand (medium)Sand (coarse)Gravel (fine)Gravel (medium)Gravel (coarse)SiltClayLimestone

471013

28729714333139

2992732

0.02 - 0.400.12 - 0.410.01 - 0.330.01 - 0.460.16 - 0.460.18 - 0.430.13 - 0.400.17 - 0.440.13 - 0.250.01 - 0.390.01 - 0.180.00 - 0.36

0.210.270.120.330.320.300.280.240.210.200.060.14

Metamorphic RocksSchist 11 0.22 - 0.33 0.26

Source: Modified from McWhorter and Sunada, 1977 (Original Reference Morris andJohnson, 1967).

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The intrinsic permeability of the geologic media is independent of thenature of the fluid flowing through the media. Intrinsic permeability is relatedto hydraulic conductivity, which is a measure of the ability of the geologicmedium to transmit water, but the terms are not interchangeable. Hydraulicconductivity is a function of properties of both the media and the fluid. Although confusing, hydraulic conductivity is often referred to as simply“permeability”. Geologic media with high hydraulic conductivities arehighly permeable and can easily transmit non-viscous fluids, especially waterand many types of petroleum products. Various geologic media tend to havehydraulic conductivity values within predictable ranges (Exhibit III-7).

A geologic medium is described as “isotropic” if the measuredpermeability is the same in all directions. Flow through an isotropicmedium is parallel to the hydraulic gradient. This condition might exist in auniform, well-graded sand. The permeability of a geologic medium is oftenobserved to vary depending upon the direction in which it is measured. Known as “anisotropy”, this condition can cause the flow of groundwaterand free product to occur in a direction that is not necessarily the same asthe principle direction of the hydraulic gradient. Because of anisotropy, acone-of-depression formed around a pumping well may be asymmetrical(e.g., elliptical) rather than circular. Sediments that are comprised of a highproportion of flat, plate-like particles (e.g., silt, clay) which can pack tightlytogether and foliated metamorphic rocks (e.g., schist) often exhibitanisotropy. Anisotropy may occur in three dimensions. For example, inflat-lying sedimentary units, horizontal permeability is usually much greaterthan vertical permeability.

The nature of geologic processes results in the nonuniform depositionand formation of rocks and sediments. Geologic media often arecharacterized by the degree of uniformity in grain size and properties such aspermeability. Geologic media with uniform properties over a large area arereferred to as being homogeneous. By contrast, geologic media that vary ingrain size from place to place are called heterogeneous. In nature,heterogeneity is much more common than homogeneity. Soil properties (e.g.,permeability, texture, composition) can be dramatically different over shortdistances. These changes strongly influence the direction and rate of theflow of groundwater, free product, and vapor through the subsurface. Forexample, free product may migrate farther and faster than it would inhomogeneous media because hydrocarbons tend to move through the mostpermeable pathways and bypass extremely low permeability zones. Fine-grained fractured media are heterogeneous in the extreme. Migrationdistances in fractured media can be large because of the very small storagecapacity of the fractures.

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Exhibit III-7

Range Of Values Of Hydraulic Conductivity And Permeability

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Properties Of Fluids

The physical properties of fluids that are most significant to freeproduct recovery and migration are density and viscosity. Densitydetermines the tendency of free product to accumulate above the watertable or to sink to the bottom of the aquifer. Common petroleumhydrocarbons tend to accumulate above the water table because of theirlow density. Viscosity is a factor controlling the mobility andrecoverability of liquid hydrocarbons. Petroleum hydrocarbons with lowviscosity are more mobile and are more easily recovered than those withhigh viscosity. A third fluid property is interfacial tension, which isimportant because it determines how easily a geologic media will be wettedwith a fluid and also controls (with pore size) the height of the capillary risein a porous media. All three properties are inversely related totemperature. Exhibit III-8 summarizes the significance of fluid propertiesand their relevance to free product recovery.

Density

Density, which refers to the mass per unit volume of a substance, isoften presented as specific gravity (the ratio of a substance’s density to thatof some standard substance, usually water). The densities of petroleumhydrocarbons typically found in USTs are less than 1.0 and typically rangefrom 0.75 g/ml to as high as 0.99 g/ml. Density varies as a function ofseveral parameters, most notably temperature, however, in most subsurfaceenvironments the temperature (and hence the density) remains relativelyconstant. The density of water is about 1.0 g/ml at normal groundwatertemperatures. Densities of some common petroleum hydrocarbons arepresented in Exhibit III-9. For a more detailed list of hydrocarbons and theirproperties, see Eastcott et al. (1988).

Petroleum hydrocarbons that are less dense than water will float;these are also referred to as light non-aqueous phase liquids, or LNAPLs. It is important to know the density of free product at a release site becausewater levels measured in monitor wells that also contain free product mustbe corrected to account for the different densities of water and the productand the thickness of the product layer. The correction procedure isdemonstrated in Exhibit III-10. Density is also a required parameter forsome volume estimation methods, which are discussed in Chapter IV and inthe Appendix.

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EXHIBIT III-8

Functional CharacteristicsOf Fluid Properties

Property Significance

Density Density values are used to determine whether free product willfloat on top of water or sink through it. Products that float arecalled LNAPLs (light non-aqueous phase liquids). Most fuelhydrocarbons are LNAPLs. Water levels measured in monitorwells containing free product must be corrected to account forthe density and thickness of the product layer (see Exhibit III-10).

Viscosity Viscosity is a measure of how resistant a fluid is toflow—viscous fluids resist flow. Higher viscosity fluids aremore resistive to flow than lower viscosity fluids. For example,gasoline, which is less viscous than diesel fuel, flows fasterthan diesel fuel. Diesel fuel, which is less viscous than fuel oil#2, flows faster than the fuel oil.

Interfacial Tension Interfacial tension is responsible for the capillary rise exhibitedby fluids in fine-grained media. Interfacial tension is inverselyrelated to the size of the pores. Fine-grained media retain morefree product (residual saturation) than coarse-grained media.

Viscosity

Viscosity, which describes a fluid’s resistance to flow, is caused bythe internal friction developed between molecules within the fluid. Formost practical applications, viscosity can be considered to be a qualitativedescription in that the higher a fluid’s viscosity, the more resistive it is toflow. Fluids with a low viscosity are often referred to as “thin”, whilehigher viscosity fluids are described as “thick”. Thinner fluids move morerapidly through the subsurface than thicker fluids. This means that athinner petroleum product (i.e., gasoline) is generally more easilyrecovered from the subsurface and leaves a lower residual saturation than athicker petroleum product (e.g., fuel oil). Viscosity is inverselyproportional to temperature: As the temperature of the fluid increases, theviscosity decreases. The efficiency of free product recovery may bereduced at sites in northern areas if temperatures in the shallow subsurfacedecrease significantly during the winter months. The viscosity of freeproduct in the subsurface environment typically changes over time,becoming thicker as the thinner, more volatile components evaporate anddissolve from the liquid hydrocarbon mass.

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Exhibit III-9

Density And Dynamic Viscosity Of Selected Fluids

FluidDensity, DD

(g/ml)

Dynamic (Absolute)Viscosity, µ

(centipoise, cP)

Water 0.998 1.14

Automotive gasoline 0.729 0.62

Automotive diesel fuel 0.827 2.70

Kerosene 0.839 2.30

No. 5 jet fuel 0.844

No. 2 fuel oil 0.866

No. 4 fuel oil 0.904 47.20

No. 5 fuel oil 0.923 215.00

No. 6 fuel oil or Bunker C 0.974

Norman Wells crude 0.832 5.05

Avalon crude 0.839 11.40

Alberta crude 0.840 6.43

Transmountain Blend crude 0.855 10.50

Bow River Blend crude 0.893 33.70

Prudhoe Bay crude 0.905 68.40

Atkinson crude 0.911 57.30

LaRosa crude 0.914 180.00

Notes: all measurements at 15EC.g/ml = grams per milliliterC = Celsius

Source: API, 1996. A guide to the Assessment and Remediation toUnderground Petroleum Releases, 3rd edition. API Publication1628, Washington, DC. Reprinted courtesy of the the AmericanPetroleum Institute.

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hc ' hm% (Ho

Do

Dw

)

hc ' 80.25 ft % 4.75ft x 0.73g/ml1.0g/ml

' 83.72 feet

Exhibit III-10

Correction To Compute Hydraulic HeadIn Wells

Containing Free Product

Equation: To obtain a corrected hydraulic head value when freeproduct (liquid hydrocarbon) is present in a well:

where:hc = hydraulic head corrected (ft)hm = measured elevation of hydrocarbon-water interface (ft)Ho = thickness of hydrocarbon layer (ft)Do = hydrocarbon density (g/ml)Dw = water density (g/ml); usually assumed = 1.0

Example: The distance from the well head to the hydrocarbon-air interface is 15.00 feet. The hydrocarbon-water interface is measured at 19.75 feet. The elevation ofthe top of the well head is 100.00 feet above sea level. The density of thehydrocarbon is 0.73.

What is the hydraulic head in this well?

Solution: The elevation of the air/hydrocarbon interface is 85 feet above sea level(100.00 feet - 15.00 feet). The elevation of the hydrocarbon-water interfaceis 80.25 feet above sea level. The hydrocarbon thickness is 4.75 feet (19.75feet - 15.00 feet). Substituting the appropriate values into the equation:

Note that the hydraulic head elevation (83.72 feet) is significantly different from the measuredhydrocarbon-water interface (80.25) and from the measured air-hydrocarbon interface (85.00feet). Groundwater elevations based on uncorrected measurements are incorrect and flowdirections should not be determined using these values. Because the flow directions areincorrect, a recovery system designed based on them would likely be inefficient or evenineffective.

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Three different terms are commonly used to describe viscosity:absolute, dynamic, and kinematic. Absolute and dynamic are synonymousterms and are typically reported in units of centipoise (cP). Kinematicviscosity, which is equal to dynamic (or absolute) viscosity divided bydensity, is typically reported in units of centistokes (cSt). Becauseviscosity is relative, the term selected for use when comparing viscositiesfor various petroleum hydrocarbons, does not matter as long as it is thesame for all the products being compared. If a flow equation is beingsolved, be sure to use a term that expressed in units which are consistentwith the equation. Absolute (or dynamic) viscosities of commonpetroleum hydrocarbons are presented in Exhibit III-9.

Interfacial Tension

The characteristics of free hydrocarbon movement are largelydetermined by interfacial tension that exists at the interface betweenimmiscible fluids (e.g., hydrocarbon, air, and water). Interfacial tensioncauses a liquid to rise in a capillary tube (or porous medium) and form ameniscus. The height of the capillary rise is inversely proportional to theradius of the tube (or pore spaces), which explains why the capillary rise isgreater in fine-grained porous media than in coarse-grained material. Ingeneral, higher surface tensions result in higher capillary pressure, whichmay produce higher residual saturation (Mercer and Cohen, 1990). Theinterfacial tension between a liquid and its own vapor is called surfacetension.

Interfacial tension is the primary factor controlling wettability. Thegreater the interfacial tension, the greater the stability of the interfacebetween the two fluids. The interfacial tension for completely miscibleliquids is 0 dyne cm-1. Water (at 25EC) has a surface tension of 72 dynecm-1. Values of interfacial tension for petroleum hydrocarbon-watersystems fall between these two extremes (Mercer and Cohen, 1990).Interfacial tension decreases with increasing temperature and may beaffected by pH, surface-active agents (surfactants), and gas in solution(Schowalter, 1979). Some of the theoretical methods for estimating freeproduct volume in the subsurface and some multiphase flow models requirevalues of interfacial tension as input. Obtaining accurate values is difficultfor a couple of reasons. First, measurement of interfacial tension in thefield is generally not practical. Second, although values for somepetroleum hydrocarbons may be obtained from the literature, these valuestend to be for pure compounds under ideal conditions and may not berepresentative of free product plumes in the subsurface environment.

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Properties Of Fluids And Geologic Media

The movement of free product in the subsurface also depends uponseveral factors which are functions of properties of both the fluid and thegeologic media. These factors are capillary pressure, relative permeability,wettability, saturation, and residual saturation. Although all of thesefactors are interrelated, the most important are capillary pressure andrelative permeability. Exhibit III-11 summarizes the most significantproperties of both the fluid and the geologic media and illustrates howthese properties relate to free product recovery.

Capillary Pressure

Capillary pressure is the difference in pressure observed betweentwo phases (e.g., hydrocarbon liquid and water) that occupy the same porespace. As the result of interfacial tension, the boundary between twoimmiscible phases is a curved surface, or interface. Capillary pressure isthe change in pressure across this curved interface. In the vadose zonecapillary pressure is negative (i.e., less than atmospheric) and is referred toas suction or tension. Capillary pressures are larger in fine-grained media(e.g., silt, clay) than in coarse-grained media (e.g., gravel). The capillaryfringe above the water table is a familiar consequence of capillary pressure. Because capillary pressure resistance is inversely proportional to pore size,the height of the capillary fringe is greater in finer grained media.

The distribution and accumulation of free product in the subsurfaceis influenced by capillary pressure. Soil water content and the size andorientation of pore spaces affect the penetration of free product in thevadose zone. Penetration of free product into the subsurface is enhancedby dry soil conditions and facilitated by inclined, relatively permeablepathways such as those provided by secondary permeability features (e.g.,fractures, root holes, and bedding plane laminations). Upon reaching thecapillary fringe, resistance to downward movement will be increased andhydrocarbons will spread laterally and accumulate above the saturatedmedia. This accumulation is sometimes referred to as a “lens” or“pancake”. As long as there is a sufficient supply of hydrocarbons fromabove, the lens thickness and downward pressure will continue to increase. Eventually, the petroleum product (the nonwetting fluid) will begin todisplace water (the wetting fluid) and enter the largest pores. The pressurerequired for this to occur is referred to as the “threshold entry pressure”(Schwille, 1988; Cary et al., 1991).

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EXHIBIT III-11

Functional Characteristics Of Properties Dependent On Both The Fluid

And The Geologic Media

Property Significance

Capillary Pressure Capillary forces restrict the movement of free product--movement tends to occur through pathways where capillarypressures are low, as in coarser-grained media. Capillarypressure is inversely related to saturation. It is not practical (ornecessary) to measure capillary pressure in the field.

Relative Permeability Relative permeability is a function of saturation and alsocontrols the mobility of liquids in a porous medium. Relativepermeability and saturation are directly proportional. In mediawith two liquids present, the permeability of the media isreduced for each liquid due to the presence of the other liquid.

Wettability Most geologic materials are preferentially wet by water asopposed to free product (or air)--this means that water, ratherthan free product will be more mobile.

Saturation Saturation controls the mobility of liquids (water and freeproduct) through a porous medium--for a liquid to be mobile,the liquid phase must be continuous and the media must be atleast partially saturated. Saturation levels are also used todetermine the volumes of free and residual product.

Residual Saturation Liquids drain from a porous medium until a certain minimumsaturation level is reached (for free product this is “residualsaturation”) and flow ceases.

Similarly, in the saturated zone, hydrocarbons will tend to spreadlaterally over fine-grained capillary barriers and move through fractures andcoarser media wherever possible. The thickness or height of a hydrocarboncolumn required to develop sufficient hydrocarbon pressure head to exceedcapillary force resistance is known as the critical hydrocarbon thickness (orheight). Because capillary forces can restrict the migration of free productinto water-saturated media, fine-grained layers can act as capillary barriers. That is, before free product can penetrate a water-saturated porousmedium, the hydrocarbon pressure head must exceed the resistance of thecapillary forces (Schwille, 1988). In heterogeneous media, free producttends to move through pathways where capillary effects are weak, such aslenses of sand and gravel or large fractures.

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Although capillary pressure is not measured in the field (it can bemeasured in the laboratory or estimated from grain size data [Mishra et al.,1989]), the effects of capillary pressure should be considered in the analysisof field data. A commonly measured field parameter is the thickness ofproduct in a well, however, this thickness is usually much greater than thetrue thickness of free product in the aquifer. This exaggeration is mostpronounced in media with strong capillary effects (e.g., fine grained siltsand clays) and least pronounced in media with weak capillary effects (e.g.,sands and gravels). Exhibit III-12 illustrates this effect, however, theexhibit is not intended to be used to estimate the amount of free product ata particular site. This effect obviously is of great practical significance inthe design of a free product recovery system. For example, thick oilaccumulations in monitor wells may be caused by either significant amountsof free product or small amounts of free product in fine grained media. Aconventional recovery system (e.g., skimmer) may be appropriate incoarser-grained media with thick accumulations of free product. In thecase of thinner accumulations in finer-grained media, a vacuum-enhancedrecovery system, rather than a conventional recovery system, may berequired.

Relative Permeability

The effectiveness of a recovery system to collect free productdepends upon the mobility of the free product through the geologic media. Mobility is strongly controlled by the relative permeability of the petroleumhydrocarbons and water, which in turn is dependent upon saturation. Relative permeability is the ratio of the effective permeability of a fluid at aspecified saturation to the intrinsic permeability of the medium at 100-percent saturation (Mercer and Cohen, 1990). The relative permeability ofa particular geologic media that is completely saturated with a particularfluid is equal to the intrinsic permeability. When more than one fluid (i.e.,air, water, petroleum hydrocarbon) exists in a porous medium, the fluidscompete for pore space thereby reducing the relative permeability of themedia and the mobility of the fluid. This reduction can be quantified bymultiplying the intrinsic permeability of the geologic media by the relativepermeability. As with saturation, the mobility of each fluid phase presentvaries from zero (0 percent saturation) to one (100 percent saturation).

An example of relative permeability curves for a water-hydrocarbonsystem is shown in Exhibit III-13. The curves representing watersaturation and hydrocarbon saturation are contrary to one another anddivide the figure into three flow zones. Zone I, where hydrocarbonsaturations are relatively high, is dominated by hydrocarbon flow. Water

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Exhibit III-12

Ratio Of Apparent To True Free Product Thickness

Measured In A Monitor Well For Various Soil Types

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Exhibit III-13

Hypothetical Relative Permeability CurvesFor Water And A Liquid Hydrocarbon In A Porous Medium

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saturations are relatively high in Zone III, and water flow is dominant. Mixed flow characterizes Zone II. Refer to the exhibit explanation formore details.

Because of the difficulties associated with laboratory and fieldmeasurement of relative permeability, alternative theoretical approachescan be utilized to estimate this function from the more easily measuredcapillary pressure data (Mualem, 1976; Lenhard and Parker, 1987; Luckneret al., 1989; and Busby et al., 1995). Relative permeability relationshipscan be estimated from grain size data for unconsolidated materials (Mishraet al., 1989).

Wettability

Wettability, which depends on interfacial tension, refers to thepreferential spreading of one fluid over solid surfaces in a two-fluid system(Mercer and Cohen, 1990). Because of the dependence on interfacialtension, the size of the pore spaces in a geologic medium stronglyinfluences which fluid is the wetting fluid and which fluid is the nonwettingfluid. The dominant adhesive force between the wetting fluid and mediasolid surfaces causes porous media to draw in the wetting fluid (typicallywater) and repel the nonwetting fluid (typically hydrocarbon or air) (Bear,1972). Liquids (hydrocarbon or water), rather than air, preferentially wetsolid surfaces in the vadose zone. In the saturated zone, water willgenerally be the wetting fluid and displace LNAPL (Newell, et al., 1995). Whereas the wetting fluid (usually water in a hydrocarbon-water system)tends to coat solid surfaces and occupy smaller openings in porous media,the nonwetting fluid tends to be constricted to the largest openings (i.e.,fractures and relatively large pore spaces). When a formerly saturatedporous media drains, a thin film of adsorbed wetting fluid will alwaysremain on the solid.

The factors affecting wettability relations in immiscible fluidsystems include mineralogy of the geologic media, the chemistry of thegroundwater and the petroleum hydrocarbon, the presence of organicmatter or surfactants, and the saturation history of the media. Sometimes,such factors can lead to the preferential wetting of only a portion of thetotal surface area; this is called fractional wettability. With the exception ofsoil containing a high percentage of organic matter (e.g., coal, humus,peat), most geologic media are strongly water-wet if not contaminated byNAPL (Mercer and Cohen, 1990). This means that free product will beless mobile and generally leave a higher residual saturation in the soil, thanwill water.

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Anderson (1986a, 1986b, 1986c, 1987a, 1987b, and 1987c)prepared an extensive literature review on wettability, its measurement, andits effects on relative permeability, capillary pressure, residual hydrocarbonsaturation, and enhanced hydrocarbon recovery.

Saturation

The level of saturation possible in a subsurface media has severalimplications for recovering free product. First, it controls the mobility offluids; second, it defines the volumetric distribution of petroleumhydrocarbons (discussed in Chapter IV); and third, it is a function of otherproperties (e.g., capillary pressure, relative permeability). The mobility of aparticular phase is reduced with decreasing saturation until flow ceases tooccur. Saturation of a porous medium may be defined as the relativefraction of total pore space containing a particular fluid (Newell et al.,1995). The saturation level for each of the fluids ranges between zero (thefluid is not present in the porespace and saturation is 0 percent) and one(the fluid completely occupies the porespace and saturation is 100 percent). Of course, a given pore space can only be filled to a maximum of 100percent, and the proportions of each phase saturation must sum to 1 (or100 percent saturation).

The mobility of a liquid through a porous medium is a function ofthe saturation of the porous medium with respect to that liquid. In orderfor it to flow through a porous medium, a liquid must be continuousthrough the area where flow occurs. As liquid drains from the media, theliquid phase becomes discontinuous. The point at which the saturationlevel for a continuous liquid phase other than water (i.e., petroleumhydrocarbon) becomes discontinuous (and hence immobile) is known as theresidual saturation (Newell, et. al., 1995). The corresponding saturationlevel for water is called the irreducible water saturation. At these lowsaturations, capillary pressures are very high.

The wetting and draining cycles of a porous media differ from oneanother as the result of differences in saturation, wettability, and capillarypressure. During drainage, the larger pores drain the wetting fluid (i.e.,water) quickly while the smaller pores drain slowly, if at all. Duringwetting, the smaller pores fill first, and the larger pores fill last. Theconsequence of this phenomenon is that the vadose zone will retain lessresidual petroleum hydrocarbon than the saturated zone.

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Residual Saturation

Residual saturation refers to the saturation level at which acontinuous mass of petroleum hydrocarbons (NAPL) becomesdiscontinuous and immobilized by capillary forces (Newell, et al., 1995). Residual saturation is important to free product recovery, because itrepresents the amount of petroleum that cannot be recovered by pumpingor gravity drainage. Following a release of petroleum hydrocarbons intothe subsurface, the hydrocarbon mass seeps downward into the unsaturatedzone. If the volume of the release is enough to sufficiently saturate the soil,the leading edge of the hydrocarbon mass continues to move deeper intothe subsurface. Behind and above the leading edge, a significant portion ofthe hydrocarbon mass is retained in pore spaces by capillary forces. Theamount of hydrocarbon that is retained against the force of gravity isreferred to as the residual saturation. The corresponding term for water isirreducible water saturation.

Generally, the finer-grained the soil, the higher the residualsaturation. Residual saturation for the wetting fluid is conceptuallydifferent from that for the nonwetting fluid. When the wetting fluid (i.e.,water) drains from a porous media, even at the level of the irreduciblewater saturation, there is a thin, continuous layer of water occupying thesmallest pores and coating the grains of the media. As the nonwetting fluid(i.e., petroleum hydrocarbon or NAPL) drains from a porous media, thepores drain incompletely because of the residual water that remains in thesmallest pores. The result is that discontinuous blobs of immobilepetroleum hydrocarbon remain in the soil at the level of the residualsaturation. More viscous fluids tend to have higher residual saturationsthan less viscous fluids. Fluids that are more dense for a given viscositydrain to a greater degree under the influence of gravity than do less densefluids. Fluids that have high interfacial tension also tend exhibit highercapillary pressure, which may result in higher residual saturation. Althoughfield-scale values for residual saturation are difficult to either measure oraccurately estimate, in general, residual saturation levels tend to be muchhigher in the saturated zone (0.15 to 0.50) than in the unsaturated zone(0.10 to 0.20) (Mercer and Cohen, 1990).

Because residual hydrocarbons are both tightly bound anddiscontinuous in pore spaces, they are essentially immobile and, therefore,not amenable to collection by standard free product recovery methods. However, the residual phase often represents a potential long-term sourcefor continued groundwater contamination. Although some portion of theresidual mass will be slowly diminished (i.e., will naturally attenuate) overtime as the result of dissolution, volatilization, and biodegradation,

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more aggressive remedial action may be required to mitigate this sourcewithin a reasonable amount of time.

Groundwater Flow Conditions

The subsurface can be divided into two zones based on watercontent: The unsaturated zone and the saturated zone. The movement ofpetroleum hydrocarbons in the subsurface is fundamentally different in theunsaturated and saturated zones. The boundary between these two zonesis commonly accepted to be the water table, which is the surface wherewater pressure equals atmospheric pressure. Below the water table, in thesaturated zone, all pore and void spaces are filled with water and waterpressure is greater than atmospheric pressure. Water pressures above thewater table, in the unsaturated zone, are less than atmospheric pressure,and the water may be considered to be under tension or suction. Directlyabove the water table is a relatively thin zone—the capillary fringe—that issaturated with water but the water pressure is less than atmosphericpressure. The capillary fringe is thicker in fine-grained media and thinner incoarse-grained media. Above the capillary fringe in the unsaturated zone,voids and pore spaces are filled primarily with air and varying amounts ofwater as either liquid or vapor.

Petroleum hydrocarbon migration is strongly affected by essentiallythe same factors that govern groundwater flow. In general, liquidhydrocarbons move in the same direction as groundwater but at a reducedrate because of the higher viscosity of the hydrocarbons (except forgasoline) and the lower relative permeability of the porous medium. Important characteristics of the groundwater flow system that influencefree product are depth to water and hydraulic head variations across thesite. Direct measurements of depth to water and water tableelevations/head are necessary to design or evaluate most free productrecovery systems. Exhibit III-14 summarizes the characteristics of thegroundwater flow system that are most relevant to free product recovery.

Depth To Water Table

The depth to water table is an important factor that affects how thefree product migrates and how its recovery should be approached. Exceptfor very deep water tables, the depth to the water table can be determinedthrough relatively inexpensive borings or monitoring wells (or well points). The depth to water table will indicate the potential for petroleumhydrocarbons to reach the water table, where the free product can then becollected in wells or trenches. All other factors being equal, a greater

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EXHIBIT III-14

Functional Characteristics OfGroundwater Conditions

Property Significance

Depth to Water Table Mass of free product required to reach the water table increaseswith depth; options to recover free product become more limited(e.g., depth must be less than 20 feet for trenching); costs torecover free product increase with depth.

Groundwater Elevation Groundwater elevation (hydraulic head) determines hydraulicgradient and direction of groundwater flow and free productmigration—presence of free product requires that measuredgroundwater elevations be corrected to account for the densityand thickness of the free product layer (see Exhibit III-10).

depth to water table requires a greater volume of liquid petroleumhydrocarbons to reach the water table.

The depth to water table, or the top of the free product layer in awell or trench, is a critical consideration in the selection of a recoveryapproach and equipment specification. For example, excavation depth isconstrained by equipment limitations, and excavation costs increasesubstantially with depth in nearly all cases. Thus, recovery systemsutilizing drains or gravel-filled trenches are typically limited to sites withwater tables less than 20 feet deep and preferably closer to 10 feet deep. Excavated material may be highly contaminated and require appropriatehandling and disposal. In most cases where the depth to the water table isgreater than 20 feet, wells must be installed.

Groundwater Elevation (Hydraulic Head)

Measurements of groundwater elevations in wells and piezometers(a well open to a narrow interval) are the basic response data thatcharacterize the direction of groundwater flow. The basic principle ofgroundwater hydrology is described by Darcy’s Law, which relates flowthrough porous media to the hydraulic gradient. Groundwater flowsdowngradient; that is, from areas of higher head to areas of lower head. The hydraulic gradient is the change in head per unit distance at a givenpoint and given direction. In an unconfined aquifer, the hydraulic gradient

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is defined by the slope and direction of dip of the water table. A commonobservation at many UST sites is a groundwater mound created by theinfluence of the tank excavation. These excavations are typically filled withpea gravel which has a much higher permeability than the native soils at thesite. As a result, tank excavations tend to accumulate and hold water,usually at a higher hydraulic head than the local water table. This cancause the formation of a localized groundwater mound that can influencethe hydraulic gradient at the site, possibly inducing free product to migrateoutward in all directions from the source of the release.

Because petroleum hydrocarbons have a density different from thatof water, neither the measured elevation of free product nor the measuredelevation of water in a well containing free product represents hydraulichead. Measured fluid elevations in monitoring wells must be corrected todetermine groundwater flow directions and rates. The equation for thiscorrection and an example calculation are presented in Exhibit III-10.

Relevance To Free Product Recovery

This chapter has presented many factors that influence theoccurrence and movement of free product in the subsurface. This sectionpresents a discussion limited to those factors that are most relevant to therecovery of the principal types of petroleum products typically stored inUSTs (i.e., gasolines, middle distillates, and heavy fuel oils). A summaryof these factors is provided in Exhibit III-15.

The majority of petroleum hydrocarbons stored in USTs are lighterthan water, which means that they float. Free product generally moves inthe same direction as the flow of groundwater. This movement is stronglyinfluenced by soil heterogeneity and anisotropy, and the design andoperation of an effective free product recovery system is dependent uponaccurate characterization of the hydrogeologic conditions at the site. It isextremely important to realize that the elevations of liquid surfaces in amonitoring well containing both groundwater and free product is notrepresentative of hydraulic head at that location. The measurement mustfirst be corrected to account for the thickness of the free product and itsdensity. Other critical factors to consider are the total volume of therelease and the depth to groundwater. If the volume of release is so smallthat there is no accumulation at the water table, then recovery of freeproduct is not practical.

Gasolines are significantly less viscous than water. They can movemore rapidly through geologic media than water and subsurfaceaccumulations can be relatively easily recovered. Many of the principal

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Exhibit III-15

Most Important Factors InfluencingFree Product Recovery

Factor Significance

Soil Heterogeneityand Anisotropy

Controls direction of free product migration and theflow of groundwater

Product Viscosity Affects mobility, ease of recoverability, and level ofresidual saturation

Soil Permeability Controls rate of free product migration and the flow ofgroundwater

Depth to Water Table Coupled with volume of release, determines whichremedial technologies may be effective at the site

Volume of Release Coupled with depth to water table, determineswhether free product recovery is practical ornecessary

components of gasoline are volatile and somewhat soluble. Because oftheir high mobility and vapor generation potential, recovery measuresshould be initiated as soon as possible after a gasoline release has beendiscovered. The lighter components also tend to be more soluble andgroundwater supplies can easily be contaminated. Residual soil saturationis lower than for the heavier and thicker petroleum products. Oldergasoline plumes will be enriched in the heavier, less volatile fractions; theymay behave more like a fresh middle distillate plume. As a result of theabsence of the volatile fractions, vacuum technologies will be less effectivein recovering petroleum hydrocarbons due to volatilization (evaporation),but vacuum-enhancement may be effective in recovering a greaterproportion of the plume than would be possible without the enhancement.

Middle distillates and heavy fuel oils are significantly more viscousthan water. Their movement through the subsurface is typically slow. Although not as volatile as gasoline, vapors emanating from middledistillate plumes can create situations in which fire, explosion, or toxicitythreatens human health and safety. Because of the higher viscosity andlower volatility, residual soil saturation is higher for plumes comprised ofmiddle distillates and heavy fuel oils than for gasoline plumes.

Recovery of free product to the maximum extent practicable ismerely the first step in a typical remedial action. Regardless of what type

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of petroleum product was released and the characteristics of the subsurfacematerials, a significant portion of the total release volume will not berecoverable by any existing remedial technology. Appropriate treatment ofthe residual hydrocarbon mass may require application of a combination ofalternative remedial technologies.

Primary References

API, 1996. A Guide to the Assessment and Remediation of UndergroundPetroleum Releases, Third Edition, API Publication 1628,Washington, D.C.

EPA, 1990. Assessing UST Corrective Action Technologies: EarlyScreening of Cleanup Technologies for the Saturated Zone,EPA/600/2-90/027, Risk Reduction Engineering Laboratory,Cincinnati, OH.

Mercer, J.W., and R.M. Cohen, 1990. A review of immiscible fluids in thesubsurface: Properties, models, characterization, and remediation,Journal of Contaminant Hydrology, 6:107-163.

Newell, C.J., S.D. Acree, R.R. Ross, and S.G. Huling, 1995. Light Non-aqueous Phase Liquids, EPA-540-5-95-500, USEPA/ORD Robert S.Kerr Environmental Research Laboratory, Ada, OK.